unitisation and redetermination—sean rush · 4 m. hammerson, upstream oil and gas: cases,...

CHAPTER 4

Unitisation and Redetermination—SeanRush

I�TRODUCTIO�

�ature ignores the boundaries within which rights are conferred by landowners orregulatory authorities to explore for and to extract petroleum. Indeed, it is oftenthe case that a petroleum reservoir straddles two or more defined explorationareas (held under concessions), wherein the rights of exploration and extractionare accordingly held by multiple consortia. To ensure the orderly developmentand production from the shared reservoir the parties to the various consortia willoften enter (whether voluntarily or as a regulatory requirement) into a unitisationand unit operating agreement (UUOA) or, into a separate unitisation agreement(UA) and unit operating agreement (UOA).1 The UUOA provides for the jointdevelopment of a common reservoir by merging the ownership interests of thedifferent consortia into an identified “unit”, defined according to the proportionof how much of the common reservoir extends into the area of their respectiveconcessions. It will contain detailed provisions whereby each unit party’s share is“redetermined” periodically on the advice of an expert appointed by the parties.This process ensures that each unit party ultimately pays for and receives anequitable share of the shared petroleum resource.

This chapter considers the nature of petroleum, the manner of the ownershipof petroleum and the case for unitisation, the use of preliminary agreements, thekey contractual terms used within a unitisation and unit operating agreement, theredetermination process, the management of UUOA disputes, alternatives toredetermination, and cross border development options.

THE �ATURE OF PETROLEUM

Petroleum is a “migratory” mineral—meaning that it moves through sub-surfaceconditions according to prevailing pressure systems applying to the strata inwhich it is found. That pressure is often released by natural occurrences, such asearthquakes, or where the rock formations between the petroleum and the surfacehave sufficient porosity and permeability that the petroleum simply migrates to

1 The reasons why a UUOA might be split into separate UA and UOAs are dealt with in detail atpara.4.19 below. A model form UUOA was issued by the Association of International Petroleum�egotiators (AIP�) in 2005, available at www.aipn.org [Accessed 25 April 2016] (and currentlyundergoing revision).

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the surface and evaporates into the atmosphere or seeps into the ocean or ontoland. In either case, the petroleum moves to the point of least pressure until iteither makes its way to the surface or until it can go no further and is trapped andsealed within a stratigraphic trap.

It is these traps that are of most interest to oil and gas exploration andproduction (E&P) companies. Once a trap has been identified the pressure withinit is released by drilling a well, causing petroleum to flow towards it andultimately to the surface. Once the petroleum is extracted it is processed andshared between the consortium which is made up of E&P companies that had therights to extract it, usually according to their joint operating agreement(JOA)—see Ch.3.

The JOA is ill-equipped to address the competing ownership and developmentrights that arise where the stratigraphic trap—the reservoir—straddles multipleproperties whose extraction rights are owned by different consortia, throughdifferent concession interests, and which are adjacent to the well. Eachconsortium has an equal right (and sometimes also an obligation) in law to accessthe common reservoir underlying the areas of its respective concession and yet ifeach consortium did so then the capital investment needed would beunnecessarily duplicated. Similarly it is often optimal to employ secondaryrecovery techniques, such as gas or water injection, into the bottom of thereservoir from wells located in an adjacent concession area in order to fully flushthe reservoir so that production recovery can be maximised from the existingproduction wells. Furthermore, an uncoordinated approach to producing thecommon reservoir may irreparably damage it, thereby reducing the maximumeconomic recovery of the interest petroleum reserves. These challenges may beovercome by aligning all interested parties under one coordinating agreement, theUUOA, which would thereby enable the maximum economic recovery ofreserves from the common reservoir in accordance with good oilfield practice.

THE OW�ERSHIP OF PETROLEUM A�D THE CASE FORU�ITISATIO�

Before examining the mechanics of the UUOA, it is worthwhile revisiting theprinciples of ownership that are relevant in petroleum exploration and productionoperations in order to understand the issues that unitisation attempts to solve:

(i) Ad coelom—under the doctrine of ad coelom, a landowner owns both therights to the land’s surface and everything above and below it as well. Thisincludes any minerals beneath the surface of a parcel of land. In manycountries however, such as the UK, the doctrine of ad coelom has beenmodified in respect of petroleum deposits so that the rights to petroleumexisting beneath the surface are vested in and owned by the state and arenot capable of being owned by a private landowner.

(ii) The law of capture—oil and gas are migratory minerals—they moveunderground depending on pressure changes—and they can be extractedfrom an adjacent parcel of land if a well relieves pressure and causes thenatural and unprompted movement of petroleum towards it. In the US,

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U�ITISATIO� A�D REDETERMI�ATIO�

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ownership of such migratory minerals has followed the same rule applyingto that of wild animals—the “law of capture” whereby a surface owneracquired property rights in an animal that strayed onto his land when it wasreduced to his possession and “captured.”2 The law of capture has been saidto apply to water rights3 under English law and it has been argued that therule must apply to petroleum underlying the United Kingdom ContinentalShelf (UKCS) due to the nature of mineral ownership thereunder, asdetermined by international law.4 However, whilst some doubt will remainover the application of the law of capture under English law, until thequestion is put fully to the English courts then it is sensible to structurecommercial arrangements applicable to a field assuming that it does soapply.5

(iii) Rights of extraction—an owner of land may permit another to enter ontohis property and remove the mineral resources. Such rights are known as“profits à prendre”. The US continues to adhere to the principle of adcoelom and surface owners commonly lease their land to E & P companiesand permit production activities in exchange for the payment of a royalty.In combination with the law of capture, this led to competitive drilling asone landowner tried to out-drill his neighbour and to deplete as much of theunderlying resource as he could before his neighbour thought about doingthe same. In most other countries the state is the owner of undergroundpetroleum deposits in situ and may award exploration and production rightspursuant to some form of concession, typically a licensing or productionsharing regime.6 These areas are usually much larger than the parcels ofland individual landowners might lease to E&P companies in the US and sothe capacity for a single reservoir to straddle the boundary of multipleconcessions is somewhat reduced.

�evertheless, where a reservoir straddles multiple concessions then in theabsence of an alternate legal construct the common law may apply the rule ofcapture.7 As noted above, in the US this rule incentivised a landowner to drill as

2 The law of capture was first determined under US law in Westmoreland & Cambria �atural Gas Cov De Witt, 18 A. 724 (Pa. 1889). See also M.P.G Taylor, T.P. Winsor, S.M. Tyne, Joint OperatingAgreements, 2nd edn (London: Longman, 1992), p.66 for a discussion on the application of the law ofcapture in the US and UK; Rick D. Chamberlain commentary on the law of capture in, A �ewDimension in the Rateable Taking of �atural Gas in Oklahoma: Enrolled House Bill 1221, (1984) 20Tulsa L.J. 77.3 See T. Daintith et al., United Kingdom Oil and Gas Law, edited by A. Hill, 3rd edn (London: Sweet& Maxwell, 2003), para.1–723.4 M. Hammerson, Upstream Oil and Gas: Cases, Materials and Commentary (London: GlobeBusiness Publishing Ltd, 2011), paras 3.27–3.2.10.5 This suggestion is particularly applicable to long term gas sale “depletion” contracts which wereprevalent in the UK until late 1990s. Is gas from a licence area subject to such a depletion contract ifit migrated from outside the licence area but was nevertheless produced from it? This was a real issuefor British Gas in the mid-1990s as the spot price for gas plummeted and it found itself bound tocontinue purchasing gas under depletion contracts at over three times the spot price.6 In this article the generic “concession” is used to describe the rights to extract and producepetroleum from an area whether it be a lease, licence or production sharing contract. The detail ofthese concession arrangements is considered in Ch.1.7 “Capture” is defined in Jowitt’s Dictionary of English Law, 3rd edn (London: Sweet & Maxwell,2010) as “a taking, a seizure. Capture is in some cases a mode of acquiring property. Thus, everyone

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many wells on its land and to pump out as much oil and gas as fast as possiblebefore his neighbours drained the common reservoir. This wasteful activity didnot accord with good oilfield practice and led to the duplication of capital spend,poor reservoir management, no secondary recovery and ultimately less petroleumbeing extracted. The increased production also led to the over-supply of oil andgas in the region of operations, reducing the regional market price for oil and gasproducts, and accelerating the early abandonment of wells. In all, this wastefulactivity, although incentivising the fast-track development of the early petroleumindustry, ultimately led to sub-optimal developments and a reduction in totalultimate recovery from a field—with a consequential reduction in revenue to thelandowner and to the state authorities.

To ameliorate the problem many oil producing states regulated the amount ofspace between each well leading to “pooling.” Pooling differs from unitisation asowners who cannot meet the regulatory spacing threshold to drill a well cancombine with others to do so. However, the “pool” is an aggregation of surfaceland and subsurface extraction rights and therefore not limited to one commonreservoir meaning drilling may target multiple geologic structures.8 Unitisationon the other hand applies strictly to one common reservoir. The UK, whosepetroleum licence areas covered vast tracts of the �orth Sea, provided as alicence condition that drilling could not take place within 125m of the licenceboundary, which incentivised adjacent owners to undertake commercial discus-sions where a reservoir may straddle the concession boundary. However, moreoften than not such discussions led to unitisation, because it constrained theextent of the aggregated area, leaving the potential for large undiscoveredstructures that could exist wholly within the unexplored areas of the licences, tothe relevant concession holders and not the “pool”. In addition, the UKGovernment may require unitisation where in the national interest to do so and itis now a standard power that most governments reserve for themselves shouldcompetitive production activity undermine the maximum economic recovery ofreserves.9

It is perhaps worth noting at this point that in addition to the regulatorydifferences noted above, the practical differences between a unitised fieldonshore in, for example, Texas, and offshore on the UKCS, complicates anygeneric analysis of unitisation. This is because the differences in the commercialenvironment within which each field is situated, means that commercialstructures that work in one area will not necessarily work well, or at all, or be

may, as a general rule, on his own land, as on the sea, capture any wild animal and acquire a qualifiedownership in it by confining it, or absolute ownership by killing it”.8 “Pooling” has been defined as: “a pool or a pooled unit is the joining together or a combination ofsmall tracts or portions of tracts for the purpose of having sufficient acreage to receive a well drillingpermit under the relevant State spacing laws and regulations, and for the purpose of sharingproduction by interest owners in such a pooled unit” (Bruce M. Kramer & Patrick H. Martin, The Lawof Pooling and Unitization, 3rd edn (Matthew Bender, 2006)).9 See Asmus et al., “Unitizing Oil and Gas Fields Around the World: A Comparative Analysis of�ational Laws and Private Contracts” (2006) 28 Houston Journal of International Law 3, 24–25where the authors note that most countries in their study had legislation dealing with unitisation andcompulsory unitisation where agreement between owners cannot be reached. The paper is availablewithout charge at University of Houston Law Center’s Public Law & Legal Theory Series On theSocial Science Research �etwork web site at http://papers.ssrn.com/sol3/papers.cfm?abstract_id=900645 [Accessed 25 April 2016] .

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needed in the other. The key differences are in cost, schedule and the availabilityof production and evacuation facilities. Onshore wells are almost invariablycheaper, less technically complex and of shorter duration. Drilling an onshorewell in a shallow gas reservoir may take a mere half day to drill with a land basedrig that is easily trucked to and from the well site. The ease of logistics andcomparatively small cost provides ample opportunity for individual E & Pcompanies, who believe the common reservoir extends further into their tract (see4–20 (xii) below), to fund their own drilling to prove up their claim (although,often times it is the reverse that happens). In fact, it has been observed that in�orth America unitisation, whether compulsory or voluntary, usually only takesplace after the commencement of production and when secondary recoverymethods need to be employed.10 Conversely, drilling an offshore well is far moreexpensive and logistically challenging. A UKCS well programme may take a yearor more to plan, over a month to drill, if suitable rigs are available, and at a cost(at least until recently) of up to US $500,000 a day. If there is a platform fromwhich the well can be drilled its use will be limited in terms of bed space and well“slots” by which to accommodate a participant’s desire to prove up its own tract(and this will be exacerbated where the interests of the unit operator (see below)are not served by the drilling of such a well). Secondary recovery techniques willform part of the early thinking for end of field life production and, with thepotential for disaffected licence holders to appeal to the regulator, it is consideredbetter to attempt to land an agreement. As such, the commercial dynamics of anonshore versus offshore unit development are very different and these significantdifferences must be kept in mind when the UUOA is being negotiated and theredetermination process is being fleshed out. For the purposes of this chapter, theanalysis which it contains is primarily directed at an offshore conventional unitdevelopment, although many of the principles will apply to onshore develop-ments, especially where the state owns the resource and awards one form ofpetroleum exploration and/or production concession or another to an E&Pcompany.

The aspiration that is common to any type of unitisation is that by applying theprinciples of unitisation (and of any subsequent redetermination) the participatingconsortia will become commercially aligned by sharing risks and rewardsequitably, thereby facilitating the optimal technical development and productionof the petroleum resource. How well this aspiration is realised in practice willdepend upon how well the UUOA is drafted, negotiated and applied in practice.

THE USE OF PRELIMI�ARY AGREEME�TS

In the simplest of terms, the UUOA is a form of JOA but whose applicationapplies across two or more adjacent concession areas. The unitisation processinvolves the owners establishing the extent of the common reservoir (the “unitinterval”) and then ascribing a proportion of that unit to each of the underlyingconcession groups, thereby creating each concession group’s “tract”11 with the

10 See Taylor et al., Joint Operating Agreements (1992).11 As defined in the AIP� model form UUOA and also see the Petroleum Joint Venture AssociationModel form Unit Agreement available in O’Brien’s Encyclopaedia of Forms, Ch.42.

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resultant proportion that the tract bears to the total common reservoir being theconcession group’s “tract participation”.12 The tract participation is thenmultiplied by each of the concession group owners’ participating interests (asrecorded in each underlying JOA) to give each owner’s share in the tract. A unitowner’s ownership interest in the unitised common reservoir (its “unit interest”)is the aggregate of that owner’s interests in the various tracts that make up theunit. It is each owner’s unit interest share that defines its contribution to capitaland operating costs as well as its share of the resultant production. Figure 1illustrates the methodology for determining unit interests.

Once established, the unit interests are then typically fixed for a period of timebut because the initial analysis which underpinned the unitisation will have been

12 As defined in the AIP� model form UUOA and also see the Petroleum Joint Venture AssociationModel form Unit Agreement available in O’Brien’s Encyclopaedia of Forms, Ch.42.

Figure 1: Calculation of Unit Interests

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based on very limited data, it is common for the unit interests to be revisedbetween the participating consortia using the redetermination process after aperiod of commercial production. The redetermination process is complex,requiring a multi-disciplinary team approach involving economists, geologists,geophysicists, reservoir engineers, petroleum engineers and lawyers. The changeof even a one percent unit interest in a large field through the redeterminationprocess can be worth tens and even hundreds of millions of dollars of petroleumproduction costs and revenues. Accordingly, it is important that the correctground work to allocate ownership rights is put in place from the very beginning.

Before the question of unitisation can be contemplated, evidence must beacquired suggesting that a geological structure, with petroleum bearing potential,might straddle a concession boundary. In order to better understand the structure,the two or more concession groups will incrementally learn more about thestructural extent and distribution of petroleum, if any, to establish if the structureis a common reservoir. The first step is for each group to disclose the data theyeach have collected relating to the possible joint structure and consider thepotential for the presence of a common structure that might merit unitisation.Such data might include seismic or well data from analogue or offset (parametric)wells13 that has been acquired by the individual consortium pursuant to its JOA.The exchange would normally be handled under a data exchange agreement thatprovides for mutual obligations of confidentiality.

If the potential for a common structure is identified the next step is for theparticipating consortia to jointly acquire additional data under a joint cost sharingagreement or, if drilling a well, pursuant to a joint well agreement. Because thesejoint activities involve third parties and activities outside the concession area of atleast one of the consortia, they will be outside the scope of the underlyingJOAs—hence the need for an additional agreement, wherein special rules relatingto decision making and ownership of acquired property will be incorporated, aswell as administrative matters relating to cash calls and defaults. Often thecompletion of a joint well will be sufficient to satisfy any well commitment aconsortium may owe to the government under its relevant concession andaccordingly the opportunity to share costs and complete minimum workobligations with another consortium is often attractive.

Where work completed under these preliminary agreements confirms acommercial discovery straddling a concession boundary then a pre-unitisationagreement (PUA) will often be negotiated. The scope of a PUA may vary fromproject to project depending on the alignment of the parties, the appraisal workneeded and the range of options for field development. Older fields in the UKoften relied upon an extensive and detailed document that was entered into inorder to give the participants contractual certainty of their initial unit interestsprior to the commencement of significant appraisal spending.

The PUA will define the unit and provide for the preparation of a fielddevelopment plan (FDP) that will set out how the parties propose to develop thereservoir and evacuate production from the unit to market. It will convene anoperating committee with rules for decision making. In this regard it containsmany provisions that are common to JOAs but at some point, usually prior to the

13 Offset (parametric) well data is derived from wells that may have targeted or drilled through thetarget geological formation but in an area that is distinct from the unit.

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first point of petroleum production, will be superseded by the UUOA.14 However,the PUA is usually targeted solely at what is needed to prepare and execute theFDP and accordingly the PUA is often silent on other exploration, production ordecommissioning work programmes and budgets, offtake rights and theredetermination process. FDP execution and subsequent production is oftentherefore outside the scope of a PUA and must commence under the UUOA. Assuch the UUOA is structured so as to supersede the PUA so that any workcommenced under the PUA can transition to the UUOA, which is fully equippedto deal with matters within the scope of the PUA and also the resultantdevelopment, production and subsequent decommissioning work programmes.

The key issues a PUA might address (at least on an initial basis, before beingfinalised in a UUOA) will include the following:

(i) Appointment of the pre-unit operator—the PUA will appoint a pre-unitoperator to conduct the activities envisaged under the PUA. Although thatoperatorship is usually awarded to the operator who has the highest unitinterest this may not always be the case if another operator is strongtechnically, in regards to the likely FDP requirements. The role of theoperator (appointed principally under the PUA and then progressing to theUUOA) is similar to that under a JOA. Consequently, the party appointedas unit operator will have considerable influence with regard to the FDP,the best downstream gas or oil evacuation routes, where wells are to bedrilled and other data collection processes that will be payable by the unitaccount. Additionally, under the UUOA the unit operator will be chargedwith the development of a reservoir simulation model15 depicting the unitoperator’s view of the reservoir, including its shape, projected flow rates,porosity, permeability, oil/gas in place and the estimated distribution ofboth across the common reservoir. Tract participants who share their tractwith the unit operator can therefore take comfort that the unit operator willseek to promote a FDP that proves up reserves in the unit operator’s tract,provided it can be justified as complying with good oilfield practice.Conversely, owners who are not aligned with the unit operator need to takecertain steps to protect their interests so that when a final assessment of unitinterest is undertaken, they are able to present sufficient information tocounter the unit operator’s assertions of petroleum volumes and distributionacross the common reservoir.

(ii) Convening of pre-unit operating committee—the PUA will convene apre-unit operating committee to oversee the work of the pre-unit operatorand also to convene sub-committees to advance the technical, legal andcommercial negotiations needed in developing the FDP for submission tothe regulator and advancing the UUOA draft to execution. The PUA mayalso document those matters that the parties have already agreed will be

14 Often when the FDP (formerly known in the UK as the “Annex B”) is approved. See W. English,“Unitisation and Unit Operating Agreements” in M. David (ed.), Upstream Oil and Gas Agreements(London: Sweet and Maxwell, 1996), p.102.15 Typically this will be a computer generated 3D dynamic simulation model that takes account ofwell and production data in “real” time in the sense that the model is constantly validated by theoperator against daily production or well data which over time is known as a “history matched”model.

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included in the UUOA such as voting passmarks, historic costs to beshared, the basis for redetermination and principles that might apply.

(iii) The unit interval—having discovered the common reservoir it will benecessary for the purposes of the FDP to define its extent. This is usuallydone on a three dimensional basis whereby areal latitude and longitudecoordinates are bounded by specified depths, usually defined by referenceto geological formations at the top and bottom of the strata in which thereservoir is contained. The resulting three-dimensional map is known as the“unit interval”.

It is important that the unit interval represents the best view available onthe existing data because petroleum that falls within it, or otherwisemigrates to it, belongs to the unit participants as “unit substances” and aresubject to the UUOA. If the unit interval is too small then petroleum thatfalls outside it may be extracted by the consortium that holds the rightswithin the relevant area, potentially draining the common reservoir.Conversely, if the unit interval is too large then it may capture petroleumthat is not properly in pressure communication with the common reservoirand may therefore fall wholly within one concession and be for the relevantconcession group’s individual benefit.

(iv) The unit area—the unit area will be defined by reference to longitude andlatitude coordinates. The unit area is the aggregate of the contiguous area ofeach concession group’s concession within which unit operations targetingthe unit interval may take place under the UUOA. It will include the unitinterval with an additional buffer to accommodate an increase in the unitinterval should it be warranted. Whilst it may be bounded by the bottom ofthe unit reservoir, it is not constrained by an upper level as unit operationswill take place between the unit interval and the land or sea surface. Exceptfor non-unit operations (see below at para.4–20) all activities undertakenwithin the unit area will be subject to the UUOA, whose governanceprocesses will supersede the underlying JOAs.

(v) Preparation of the field development plan—the PUA will provide for thedecision making mechanisms by which the party appointed to be the PUAoperator will develop the FDP and will submit it to the host government forapproval. In the UK guidance in regards to unitisation is given in theregulator’s Guidance on the Content of Offshore Oil and Gas FieldDevelopment Plan which makes clear that the regulator expects anyadjacent concession groups to have been consulted in regards to a fielddevelopment proposed for a field extending into a neighbouring licenseand, ideally, for the FDP to be submitted in an agreed form.16

(vi) Historic costs—agreeing which historic costs were incurred by eachconcession group for the benefit of the common reservoir will featureprominently. Historic costs expended solely by one concession group butwhich are agreed should be shared will be the subject of a rebate to theconsortia that funded them initially. The agreed costs to be shared may berepeated and supplemented in the UUOA.

16 Paragraph 2.5.1, available at https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/265842/FDP_guidance_notes_�ovember_2013_web.pdf [Accessed 8 June 2016].


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THE U�ITISATIO� A�D U�IT OPERATI�G AGREEME�T –KEY CO�TRACTUAL TERMS

A UUOA will contain terms that, not surprisingly, deal with: (i) “unitisation”, i.e.the merging of ownership interests in the common reservoir, that are held undertwo or more concessions, into a single unit and a process for how those interestsmay be altered over time; and (ii) “operations” which deal with how the commonreservoir will be developed and petroleum will be produced, including thegovernance applying to such operations. A publicly available UUOA based on theAIP� model form can be found on the SEC website.17 Many of the operationalaspects of a UUOA do not differ materially from those applying to a regular JOAand so will not be addressed in this chapter.

An initial issue of form will need to be resolved by the parties. Should theUUOA be separated into a UA and a UOA, as is the norm in the US and Canada,or should it be kept together as a UUOA, as is the practice in the �orth Sea?Splitting might be considered appropriate if the host government requires theunitisation of a reservoir to be approved by the regulator, sometimes by tabling inthe local Parliament or equivalent. Two issues arise that splitting the UUOA isintended to address: (a) the time taken for a fulsome review and approval by theregulator is likely to be shortened if the document submitted for approvalcontains only the minimum required to comply with the legislation; and (b) in theevent that a document is submitted to the regulator it may fall within the scope ofFreedom of Information Act legislation enabling disclosure to the public andpotentially revealing confidential aspects of the agreement to other competitorcompanies and regulators. This risk is particularly heightened where thedocument is tabled in Parliament. Similarly, the UUOA may be required by therules of an applicable stock exchange to be disclosed for fund raising purposes.As such, it may be particularly desirable for a unit operator to preserve theconfidentiality of the UOA aspects where thorny issues, such as full liability forits wilful misconduct, have been conceded and where publication of such couldundermine a negotiating position elsewhere. Accordingly, if the full document islikely to be subject to public disclosure then paring it back to the minimum,through splitting the document into discrete parts, might be desirable.

The timing for completing the UUOA is a matter to be agreed. A hostgovernment may require, as a condition of approving the FDP, that the UUOA isin place in order to ensure commercial negotiations do not delay the technicalexecution of the FDP.18 Many of the provisions agreed to in the PUA, includingthose summarised above, will feature in the UUOA although some terms may begiven greater attention and will consequently be refined in the final form UUOA.Other common terms applying to unitisation are as follows:

(i) Unitisation—the key difference between the JOA and UUOA is thecommitment by the differing consortia to pool their interests, as they applyto the common reservoir, and so to “unitise” their interests. A typicalformulation of a “unitisation” clause reads as follows:

17 See http://www.sec.gov/Archives/edgar/data/1509991/000104746911001716/a2201620zex-10_6.htm [Accessed 25 April 2016].18 This is the practice in the UK.

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“all rights and interests of the Parties under the [concessions] are hereby unitisedin accordance with the provisions of this Agreement insofar as such rights andinterests pertain to the Unitised Interval and each of the Parties shall own allUnit Property and Unit Substances in proportion to its Unit Interest”19

This mutual commitment is the written embodiment of the aspiration toalign all commercial interests in the common reservoir in order thatdevelopment can be undertaken coherently with the intent of maximisingthe economic recoverability of petroleum. Once the unitisation takes effectthe parties are (or ought to be) indifferent to the point where the productionis extracted or where facilities might be located.

(ii) Supremacy of the UUOA—provision is usually made for the terms of theUUOA to take precedence over any JOA (or other agreement) that mightotherwise apply to a part of the unit area. This is important so that it is clearthat decision making and the conduct of operations is determined by theUUOA. The JOA, will continue to apply outside the unit area and to anywork undertaken by one group within the unit area as a “non-unit”operation (see below para.4–20 (viii)).

Similarly the UUOA will supersede the PUA, and work that may havecommenced under the PUA may transition to and be completed under theUUOA. It is often the case that the effective date of the UUOA is stated tobe the date of the PUA (or when the first significant cash call was issuedthereunder) so that the unit interests and cost shares under the UUOA applyretrospectively to work completed under the PUA.

(iii) Tract participations and unit interests—as illustrated in fig.1, the UUOAwill allocate a proportion of the common reservoir (the unit interval) toeach consortium as its tract participation. Each tract participation is thenallocated amongst the members of each consortium according to itsparticipating interest in each underlying JOA. The aggregate of each party’sshare in each tract will be that party’s unit interest.

(iv) Decision making—like a JOA, a UUOA will provide for the establishmentof an operating committee made up of representatives of the parties (theunit operating committee (UOC)) and will define the process by whichdecisions with regard to unit operation are to be made. Because operationaldecisions, such as where to locate a production well, might either advantageor disadvantage one concession group over another in a redetermination,voting passmarks often require at least one member from each concessiongroup to vote affirmatively in addition to the usual passmark thresholdrequired under the underlying JOAs.

(v) Work programmes—the PUA will provide for exploration and appraisalactivity needed for the preparation of the FDP but implementing it may notbe within its scope, necessitating the need for the UUOA to be concluded.Unlike a JOA, it would be unusual for a UUOA to include an explorationand appraisal programme as exploration is dealt with under the preliminaryagreements with appraisal under the PUA. This is because once a discoveryhas been made and the unit interval delineated, there is no need for furtherexploration or appraisal as any production in pressure communication with

19 Paraphrased from English, “Unitisation and Unit Operating Agreements” in David (ed.), UpstreamOil and Gas Agreements (1996), p.97.

THE U�ITISATIO� A�D U�IT OPERATI�G AGREEME�T

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petroleum in the unit interval will automatically be subject to the UUOA.Petroleum that is not in pressure communication is normally outside thescope of the UUOA. However, whilst separate reservoirs that are not incommunication with the unit interval are likely to have a differentdistribution of petroleum than in the unit interval, the unit parties may wishto include a new reservoir in the unit in order to gain access to the facilitiesand a petroleum evacuation route. Strictly speaking, this would require anamendment to the UUOA because only substances within pressurecommunication of the unit interval are within its scope and “unitised.”

As such, for example, where a UUOA does not provide for a “floor” forthe unit area, so that the unit area includes all depths, then the parties to theunit will be able to conduct deeper exploration operations below the unitinterval. However, if a resultant discovery is made whereby production isshared according to the extant unit interests then the agreement could moreproperly be classified as a “pooling” agreement although the distinction isless clear (and somewhat irrelevant) if the new volumes can be consideredin a subsequent redetermination of the unit interests.

(vi) Disposition of production—another differentiator of the UUOA from theJOA is that the UUOA is negotiated in the context of a known discoveryand a draft FDP, with identified oil and gas lifting and transportationoptions. Accordingly, the “agreement to agree” language in regards to gas“special arrangements” and oil lifting “principles” that are common tomany JOA forms are replaced in a UUOA by detailed and specifiedarrangements that integrate the production rights with the offtakearrangements envisaged in the FDP. In addition, there is often a provisiondeclaring that, regardless of which concession the production originatedfrom, it shall be deemed to have been extracted from the recipient’sconcession area so that the fiscal terms applicable to the recipient’sconcession area will apply to production received.

(vii) Sole risk—sole risk is often omitted from UUOAs because the commonreservoir includes all petroleum in pressure communication with the unitinterval and is already the property of all the unit owners and shouldtherefore be capable of being produced from the production wellsenvisaged in the FDP. Undiscovered or un-appraised reservoirs that areseparate from the unit interval and that might be targeted under a sole riskoperation are not usually included in a UUOA. Where sole risk is includedit is more likely to be used by a unit party to prove up reserves in its part ofthe tract, through the drilling of a parametric well, and thereby increase itsunit interest during a redetermination. If the well is successful then it maybe “adopted” by the unit parties together who will pay for the well costs butusually without the uplift that is typical of the sole risk buy-back provisionsunder many JOAs.

(viii) �on-unit operations—non-unit operations are usually more extensivelydocumented in the UUOA as opposed to a JOA for two reasons: (a) becausethe FDP will have been developed it is a more realistic possibility that, inthe event of a new discovery in one of the concession areas, it will be mosteconomic to tie the new well back to the unit facilities and produce throughthem. As such, it is common for more detailed arrangements setting out the


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terms of use of unit facilities for non-unit operations to be included,including the use of well slots and processing capacity; and (b) often aconcession group will wish to undertake activities within the unit area thattargets a formation other than the unit interval. In such a case, the unitoperating committee will need to be informed and grant consent, whichmay be withheld if such non-unit operations interfere with planned unitoperations. Often such operations are undertaken by the unit operator inorder to ensure the unit operations are not compromised. Furthermore,should the non-unit operation involve drilling through the unit interval, anindemnity for damage to the unit interval is often required. Data recoveredin regards to the unit interval will usually be contributed, on a no-chargebasis, to the unit.

(ix) Decommissioning—most JOAs, historically, have left the thorny issue ofdecommissioning (and security therefor) until after a discovery has beenmade. However, with a UUOA, a discovery will often have been madebefore the process of unitisation gets underway so it is clear that productionfacilities will be constructed and will accordingly need to be decommis-sioned and removed. Due to the enormous costs involved in offshoredecommissioning, the UK regulator has required UUOAs to containdetailed decommissioning security provisions to ensure that funds will beon hand to pay for decommissioning after production has ceased and thishas become standard in UUOAs elsewhere.20

(x) Default—the consequences of a unit party’s failure to pay cash calls arebroadly the same under a UUOA as they are under a JOA. The keydifference however is that the unit operator may initially seek immediatepayment by way of cash call from the concession group in which thedefaulting unit party participates. This cash call then triggers a similar callunder the JOA, whereby the failure to pay then commences the process bywhich a defaulting party loses its vote, its entitlement and ultimately itsparticipating interest, including its unit interest, under the JOA. In the eventeach member of the defaulting party’s group also fails to pay theoutstanding cash call then the process by which they lose their votingrights, rights to production and ultimately unit interest might also applyunder the UUOA.

(xi) Transfer—any unit interest transfer by a unit party will necessitate thetransfer of the underlying interest in the JOA, meaning that any criteriathereunder, such as the technical and financial capacity of the assignee, willneed to be met to the satisfaction of the remaining JOA parties as well asthe other unit parties. Similarly, although the use of pre-emption clauses arecommon in UUOAs, if pre-emption rights apply under the JOA then themembers of the transferring party’s concession group will normally be ableto exercise such pre-emption rights in priority to the other parties to theUUOA.

(xii) Redetermination—the initial tract participations, and consequential unitinterests, are commonly adjusted according to a redetermination procedure.This is a key part of the UUOA and is explained in detail below. However,one difference between the UK offshore model and the �orth American

20 For example see art.12 of the AIP� model form UUOA.

THE U�ITISATIO� A�D U�IT OPERATI�G AGREEME�T

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onshore model will need to be considered. In the UK, redetermination isusually done on a concession group to concession group basis, with therespective JOA operators leading the analysis and submissions for theirgroup as part of the joint operations under the JOA. Unit owners who aremembers of two or more concession groups will be conflicted out fromparticipating in all but the concession group in which they hold the highestparticipating interest. Similar rules apply to operators under multiple JOAswhereby a “redetermination operator” will be appointed from thenon-conflicted parties. This structure is desirable to ensure that theconcession’s geological interpretation, as approved under the underlyingJOA, is considered and not an individual unit party’s view that will havebeen constructed outside the scope of the JOA, without the approval orsupport of the relevant JOA operating committee and which is almostcertain to be self-serving. Conversely, in �orth America it is standard foreach unit party to have its own voice in the redetermination process and beable to present its individually created geological model, in competition tonot only that of the unit operator but also to the operator under theunderlying JOA to which it is a party. As discussed above, an onshoreunitised field presents fewer logistical challenges and costs when comparedto an offshore field, and so there is little reason why a party to an onshoreunit would delegate the preparation of its redetermination case to anoperator whose role will have diminished considerably given the smallerconcession areas prevalent onshore. For �orth Sea fields it is much lesspracticable for a unit party to develop a geological model that can crediblycompete with that of the unit operator’s as well as that of the operator underthe relevant JOA who will likely continue to analyse other explorationopportunities within areas subject to the JOA other than the unit interval.An expert is likely to lend more weight to a model developed by anoperator pursuant to a JOA for the concession’s area, including the unitinterval, which is then approved for submission to the expert for and onbehalf of the JOA parties.

REDETERMI�ATIO�

“Redetermination” is a process whereby the unit owners agree that at one or moredates certain21 in the future they will agree to revisit the unit interests in the lightof information received from new wells or production data and, whereappropriate, will adjust the tract participations to reflect the proportion of thereservoir and associated petroleum that the new data now suggests underlies eachtract. In the absence of agreement an “expert” will be appointed to determine therevised unit interests.

The basis of, and the methodology for, the calculation of petroleum volumes isa matter for agreement in the UUOA. A number of methods are available:

21 Commonly set at a certain number of years after the commencement of production, or the drillingof the last well or after a certain percentage of estimated recoverable reserves have been produced.

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(i) Stock tank oil originally in place (STOOIP) or its gas corollary gas initiallygas in place (GIIP)—a STOOIP/GIIP approach requires a calculation of thevolume of petroleum in the reservoir, as measured in a “stock tank”, i.e. atsurface atmospheric pressure, without correction to account for othervariables such as recovery rates, quality or the timing of development costs.It is thought that most �orth Sea unitized fields utilise a STOOIP approachdue to its simplicity and ability to calculate early field life.22 STOOIP issimple but is unsuitable for more complicated reservoirs where thepetroleum recovery factor per unit of volume of rock may vary across thereservoir.

(ii) Moveable oil originally in place (MOOIP)—MOOIP is STOOIP less theestimated oil left in the reservoir at abandonment. Its simplicity makes itattractive but it can only be calculated with certainty at end of field life andneeds to accommodate the inaccuracies associated with estimatingSTOOIP.

(iii) Economically recoverable reserves—this requires assessing the maximumeconomically recoverable reserves, i.e. what will actually be produced overfield life. This is attractive for more complex reservoirs with differingrecovery rates but can be problematic because the recoverable reserves maychange depending on petroleum prices due to their influence on theeconomics of secondary or tertiary recovery expenditure.

The timing and the mechanism for calling a redetermination is important.Once the field is in production a reasonable database will have accumulatedincluding well data, which gives the best information of the characteristics of theunit interval, and production data from which the unit operator can test its view ofthe subsurface by “history matching” its reservoir simulation model outputsagainst historic production data. The more unit well data available, the better thedata set. As such the redetermination provisions will often require all wellsenvisaged in the FDP to have been drilled and be in production before a unit partymay call for a redetermination of unit interests. Usually the final redeterminationis called no later than when two thirds of the field’s estimated recoverablereserves have been produced, but more often than not a redetermination will becalled earlier.

The data set will be added to over time as more information is gathered fromunit operations and will be maintained by the unit operator as the “CommonDatabase.”23 Some commentators consider that the Common Database is strictlyfor use in redeterminations but in practice the information is (or should be) usedby the unit operator to produce the field in accordance with good oilfield practice.However, once a redetermination has been triggered the unit operator will thencollate the Common Database for delivery to each unit party and the expert.

A typical redetermination process might proceed in accordance with thefollowing sequence:

22 See Daintith et al., United Kingdom Oil and Gas Law (2003), p.1184, para.1–742 and also Tayloret al., Joint Operating Agreements (1992), p.67.23 As defined in the AIP� model form UUOA.

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(i) One unit party calling for a redetermination in accordance with the timeprescribed in the UUOA (usually after completion of the final well or aftera period of commercial production) or when an agreed number of reserveshave been produced).

(ii) Each unit party submitting its view (often known as their “Final Offer”) ofthe revised unit interests, based on the Common Database, for considera-tion by a technical sub-committee convened by the unit operatingcommittee and made up of representatives of the unit parties.

(iii) Consideration of the Final Offers by the unit operating committee andunanimous determination of the redetermined unit interests. Failingunanimity, the opportunity for any unit party to refer the redetermination toan expert for determination.

(iv) The selection of an expert and conclusion of the expert’s contract to assessthe technical merits of each Final Offer.

(v) The delivery of the Common Database by the unit operator to the expertand, if agreed, the presentation of the unit operator’s reservoir simulationmodel.

(vi) A process by which the expert may meet with all the unit parties to discussand agree preliminary issues and matters of process.

(vii) The delivery by each unit party (or each concession group) of a writtensubmission and presentation thereof to the expert setting out the competingmodel and consequential unit interest allocation.

(viii) The delivery by each unit party of written rebuttal to the other unit parties’cases.

(ix) The delivery of a preliminary report from the expert setting out its initialfindings as to tract participation and unit interests, duly supported byreference to technical analysis from the Common Database.

(x) The opportunity for any unit party to challenge the expert’s preliminaryfindings based on manifest error or compliance with the expert’sinstructions.

(xi) The delivery of the final determination and implementation of theredetermined unit interests thereafter.

Three key aspects of the redetermination process as outlined are therefore: (i)the Common Database; (ii) the expert determination; and (iii) the implementationof the redetermined unit interests. These are considered further below:

(i) The Common Database—the scope of the Common Database is often amatter for extensive negotiation. The non-contentious data for inclusion isthe data collected and charged to the unit account. This includes explorationand appraisal data that may have originally been collected under a JOA andcontributed to the development of the unit under the PUA, along with datacollected by the unit operator during the development and productionphase. It is this data that is used by the unit operator to build its reservoirsimulation model that models the subsurface characteristics of rockporosity, permeability, pressure, petroleum/water distribution across thecommon reservoir and ultimately is the key tool for forecasting productionrates and estimating the ultimately recoverable reserves. The simulation

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model is likely to be the best available model dealing with the reservoir andis a fundamental tool for reservoir management during operations and forredetermination. In order for any unit owner to credibly persuade an expertthat the unit operator’s model is incorrect and that reserves that are notaccounted for in the unit operator’s model lie in its own tract, that unitowner will need to have a full and cohesive comprehension of the unitoperator’s model. As such, it will be important that the unit operator berequired to produce the reservoir simulation model in a non-proprietarysoftware format and in a timely manner, so that a unit owner is able toassess and challenge the model or to adapt it to meet its own purposes.

Including non-unit data is more contentious and usually resisted by theunit operator and those aligned with it. However, because the redetermina-tion is based purely on what is in the Common Database it will beimportant for those unit owners that are not aligned with the unit operatorto be able to contribute well or other data proving reserves in their tract thatmay not be otherwise included in the Common Database due to that databeing obtained outside of unit operations. Unless good oilfield practiceincentivises the unit operator otherwise, the unit operator itself is unlikelyto pursue any operations that may have the effect of proving up reserves ina tract in which it has little or no interest and it would be difficult for it tojustify doing so anyway if it conflicted with its own reservoir simulationmodel. �ot only might such activity reduce the unit operator’s unit interestbut the unit operator would have to pay its unit interest share of theassociated costs. As a result, it will be important that rights in the UUOAare included allowing the submission to the Common Database of datacollected independently by a unit party or concession group under theirJOA or by virtue of the sole risk provisions in the UUOA (as describedabove, para.4–20 (vii)).

That said, it will be important that rules constraining the submission ofnon–unit data are agreed so that that the Common Database is notpopulated with a huge amount of irrelevant data as a redeterminationapproaches. One mechanism is to limit the contribution of non-unit data todata that supports a model that has been previously presented, at least inoutline, to the unit operating committee, but rejected. Limiting theCommon Database to non-unit data that supports such an alternate modelcould be one constraint that provides a unit party with the tools it needs tomount a credible challenge to the unit operator’s model without unfairlyrequiring the other unit parties to sift through an enormous amount of newand irrelevant data while preparing their own case or rebuttal.

Usually the UUOA provides for a “data cut-off” point after which nonew data is added to the Common Database. This can present difficulties,especially where the redetermination process occurs over an extendedperiod of time when new, and potentially significant, data is acquired (e.g.the unexpected watering out of a production well). To address the potentialfor an inequitable outcome, the parties may agree a later data cut-off datefor data collected from unit operations that will be acquired in a predictablemanner and readily digested.

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(ii) Expert determination—if the unit operating committee is unable to agree tothe redetermined unit interests recommended by the unit operator, thematter is 24 referred to a third party expert that is typically a reservoirmanagement service company. The expert will usually be selected by thevote of the unit operating committee. The UUOA will incorporate theprocedure to be followed by the expert. The procedures commonly usedinclude the: (a) “shot gun” approach, where the expert receives submissionsas to what the unit interests should be but delivers its own decision; (b) the“pendulum” (or “baseball” as it is known in the US) approach, where theexpert must select one of the unit owners’ suggested redetermination of unitinterests; and (c) the “guided expert” approach,25 where the expert sits withthe technical team as an observer throughout the process and is then calledupon to decide selected issues that cannot be agreed between the unitparties.26

To ensure that local arbitral legislation will not apply to the agreedprocess, it is important that the UUOA confirms that the expert is to haveno judicial function. The resultant decision is then delivered to the unitowners as a final and binding decision (subject to fraud or manifest error).However, due to the significant values involved and complexities of thesubject matter, challenges to an expert’s decision have often resulted inlengthy and costly court actions.27

When drafting the expert redetermination procedure, considerablethought should be given to how long it may take. Whilst it may beattractive to provide for a lengthy period, such as a year or more, to ensurethe expert has sufficient time to deliver a robust determination, once thebattle lines are drawn operating decisions are considered in the context ofhow they may look in front of an expert and so it is often the case thatdecisions during a redetermination are difficult to achieve leading tostagnation of decision making and, potentially, to a loss of value. Forexample, a decision to approve the acquisition of new seismic data or todrill a further producing well in one area might be interpreted as tacitsupport for the prospectivity of that area and so is unlikely to be approvedwhile the redetermination is ongoing. The flip side is for unit partiesdeferring such activity until after the redetermination in case the dataproves up reserves in an area in which they hold limited equity. If decisionsare compromised in this manner then it could compromise the maximumeconomic recovery of petroleum in accordance with good oilfield practiceand the unit’s ongoing viability. Either a shorter process should be adoptedor the parties could have an unqualified statement included in the UUOA

24 See Asmus et al., “Unitizing Oil and Gas Fields Around the World: A Comparative Analysis of�ational Laws and Private Contracts” (2006) 28 Houston Journal of International Law 3, 88.25 See Daintith et al., United Kingdom Oil and Gas Law (2003), p.1184, para.1–742,26 As used in the �elson field’s redetermination and described in Shell v Enterprise [1999] All E.R.(D) 561.27 For a discussion of the narrow range of how an expert’s decision may be challenged under thecommon law see Freedman and Farrell, Kendall on Expert Determination (London: Sweet &Maxwell, 2014), p.14.


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that decisions made by the unit operating committee cannot be used asevidence of support for one geological model over another in aredetermination.

(iii) Implementation of the redetermined unit interest—in addition to changingthe allocation of costs and production on a go forward basis to align withthe adjusted unit interests, the UUOA will provide a mechanism toreapportion historic capital costs and production that were allocated to onetract or other in accordance with the former unit interests. The methodologyis a form of banking system with production and cost “credits” and “debits”being identified, although, until redetermination occurs the unit owners cannever be sure how much debt they have accumulated or exactly when itmust be settled. The key variables and mechanisms for such an adjustmentare as follows:• Production—historic production that was allocated to unit owners in

accordance with the former unit interests is commonly adjusted byallocating a proportion of production from the unit owners whose unitinterests have been reduced to the unit owners whose unit interestshave been increased for a set period until the volumes that werewrongly allocated have been repaid or “made up”. It will beimportant that any redetermination is held far enough away fromestimated end of field life to ensure that there are sufficient volumesavailable for make up. �o account is ordinarily taken of differentialsin commodity prices which can lead to windfalls depending on thedifference in value of the volumes when originally produced and thesame volumes when produced and re-allocated as “make up”.

• Capital costs—historic capital costs and pre-production operatingexpenses are typically adjusted by a lump sum cash transfer from oneunit owner or tract group to another, with an interest component, buteven this seemingly simple process may not be without difficulty. Inone unusual case of redetermination involving the Balmoral field28

on the UKCS the capital costs were so great and the associated makeup worth so little, that the unit owners were understood to belitigating to have their unit interests reduced rather than increased,such was the failure of that field’s performance.

• Operating costs—operating costs after production commencementassociated with producing the volumes originally are not subject toreallocation on the basis that such costs will be self-adjusting byattaching to the equivalent make up volumes. This presupposes thatoperating costs on a per barrel basis remain the same throughout fieldlife, which may not always be the case.

• Alternates to “make up”—an alternative approach is for the unitowners to agree that compensation for production, capital andoperating costs wrongly allocated will be effected by a lump sumcash settlement whereby the constituent value of each element ofproduction or cost, as and when it was incurred or produced, isassessed and reconciled with a resultant cash settlement. However,due to the potentially high volume of production that may be lifted

28 See discussion by J. Ross, Industry Practice in Equity Redeterminations, TDM 2 (2004).

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between determinations and its associated value, a very smallpercentage change in unit interests can result in the cash transfer ofmany tens or even hundreds of millions of dollars between unitowners. With the more recent volatility in oil prices, a redetermina-tion that is prescribed to be made up in cash is open to all manner ofwind-falls or inequities depending on what the oil price happens to bedoing at the time of redetermination. Issues relating to the movementin foreign exchange rates and the tax treatment of a cash settlementwill also complicate this method of compensation.

THE MA�AGEME�T OF U�ITISATIO� DISPUTES

The uncertainties associated with adopting redetermination mechanisms whensigning the UUOA is at a time so far removed from the time for make up or cashsettlement provides one reason why redeterminations have been so litigious.Whilst most organisations will respect the principle that each unit party shouldreceive its fair entitlement of production, the timing for any make up and cashsettlements can be inconvenient. In times where cash has more value in the bankand credit is difficult to come by, any transfer of significant sums is likely to beresisted. Similarly, organisations providing make up volumes will be reluctant todo so in a high petroleum price environment. To minimise potentially largeswings in unit interests the UUOA can provide for unit resets in addition toseveral redeterminations. Unit resets are a “mini-redetermination” process bywhich the unit operator may reset the unit interests periodically after astreamlined process that does not involve an expert. A unit reset may be contestedwhere manifest error is involved and they may also be overturned by an expert ina subsequent redetermination. The intention of the unit reset is to enable the unitoperator to make a judgment call based on what it is seeing in the field with aview to estimating the most accurate apportionment of unit interests as possible,using the most recent production data. It is thought that with the possibility of aunit reset being over-turned for manifest error or by a subsequent expert, thecommercial incentive for a unit operator to favour its own interests areminimised. The unit reset process thus seeks to adjust the unit interests accordingto real time data. This in turn should mean that adjustments arising from asubsequent redetermination are minimised, thereby reducing the risk that itsimplementation will be excessively burdensome for some unit parties and soreducing the likelihood of an extended legal challenge.

It is commonplace for agreed settlements of disagreements relating toredeterminations to be difficult to achieve as unit owners optimise the process inan attempt to ensure that cash settlements or production reallocations occur at amore convenient time. Disagreements that would normally form the subject of anamicable settlement become protracted and often litigious, as unit owners digestthe redetermination’s value proposition.

Fundamentally, redeterminations are a technical evaluation and so, in theory,should not involve lawyers. However, for the reasons set out above, it is commonfor lawyers to take on a role that is excessively disproportionate to the volume oflegal material, which is actually put before an expert. There is much anecdotal

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evidence of experts arriving to hear technical submissions from a party, only tofind lawyers on hand, transcribing the exchanges, cautioning their clients andeven video-recording the proceedings. Such conduct can backfire as unduereliance on legal process may be viewed as a sure sign that the relevant party’stechnical case is weak.

Acting as counsel for a unit operator in a contentious redetermination requiresa fine balancing act between attempting to ensure each unit party has a fairchance to produce its preferred model but keeping within the redeterminationrules (that are often no more than guidelines), so that no unit party is undulyadvantaged. A golden rule worth bearing in mind is that the process is meant todetermine the best technical case and that, failing manifest error or the expertacting outside the terms of its agreed contractual authority to act, a court will bereluctant to overturn an expert’s decision. As such, to the extent the unit operatoror the expert is required to exercise a discretion during the course of theredetermination then the safest and most defensible approach will be the one thatallows the expert to do its job to the greatest possible extent.

A unit operator’s aspiration should be to allow the expert to make its decision,for each unit party to have a fair opportunity to present its case and for each unitparty to dutifully implement the outcome. To avoid as many debates over processas possible it is advisable to provide for the development of a prescriptivetimetable, commencing with the date that a unit party refers the unit interests toredetermination, and thereafter going through all the steps and agreed timetableuntil the expert delivers its final decision.

As noted above, with the values involved it is almost impossible for at leastthe risk of court proceedings to be avoided but at least a unit operator canminimise the number of potentially valid claims against it by acting impartiallyand in accordance with the procedure. The expert’s conduct, on the other hand, issomewhat out of the unit operator’s control and the English courts have, over theyears, been kept busy because experts have acted outside the scope of theiragreed remit. For example, in the leading English law case on this subject, theexpert used a mapping software programme other than that prescribed in itsexpert contract, which lead to a material change in the unit interestapportionment. The consequent expert determination was accordingly over-turned.29

�evertheless, some steps can be taken in drafting the expert redeterminationprocedure to minimise the possibility of an appeal to the courts later being madeby a disgruntled unit party:

(i) Provide that the decision of the expert will be final and not subject toappeal, than where fraud or manifest error are apparent.

(ii) Eliminate the misuse of the court process to defer implementation of theexpert’s decision by requiring the expert’s decision to be implemented assoon as practicable after its delivery, regardless of whether a court processmay, or has, commenced, albeit with the proviso that the implementationcan be reversed if the court so orders.

29 Shell UK Ltd v Enterprise Oil Plc [1999] All E.R. (D) 561.

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(iii) Provide terms that facilitate inter-party settlement so that a unit party (orconcession group) may either combine with another at any time orwithdraw from the process, thereby narrowing the areas of dispute forconsideration by the expert.

(iv) Give the expert a broad scope to set its own process and make its decisionfor its own reasons, within the agreed timetable. This should includeempowering the expert to determine all technical matters even if doing sorequires it to make a legal interpretation of the expert’s contract.Alternatively, if the unit parties cannot agree to such, then provide for ashort-form reference to an independent legal expert to resolve the issue.

(v) Provide an opportunity for the unit parties to review the preliminarydecision and identify any manifest errors, but leave the expert to decidewhether to incorporate any consequential amendments in the final decision.

(vi) Respect the golden rule—redetermination is a technical process wherebythe unit parties have agreed that the best technical case should prevail.Adhere to a process that best facilitates this outcome.

ALTER�ATIVES TO REDETERMI�ATIO�

The cost, distraction and (often) stagnation of decision making which isgenerated by the redetermination process has led to certain alternatives to beconsidered.30 The unit reset option (considered at para.6–26 above) has alreadybeen considered as such an alternative.

It may be argued that a unitisation process is no different to any otheracquisition process where a willing seller acquires a fixed interest in an appraisedfield for a fixed sum. In such a case there is usually no post-sale adjustment ofconsideration if the field should subsequently prove to be bigger or smaller. Assuch, the reserves risk in an appraised field are a common risk borne by E&Pcompanies as part of their day-to-day business. Consequently, it is arguable thatthe unitisation of a field poses no more or less risk and so companies should becomfortable in agreeing to fix equities once and for all, regardless of the finaloutput of the field. The drawback, of course, is that where further informationcomes to light that demonstrates that the initial unit interests were not accuratelyallocated then it would be inequitable to leave the unit interests unaltered.

Where a discovered reservoir extends into an adjacent concession area theregulator, as part of the FDP approval process, may want confirmation that theowners of such concession have been consulted and have agreed to the proposeddevelopment.31 In the absence of a UUOA there are three main contractualoptions by which this requirement may be satisfied:

30 The Prudhoe Bay redetermination was reported to cost between US $50 million and US $100million. See Asmus et al., “Unitizing Oil and Gas Fields Around the World: A Comparative Analysisof �ational Laws and Private Contracts” (2006) 28 Houston Journal of International Law 3, 84.31 This is the case in the UK. See the UK’s Guidance on the Content of Offshore Oil and Gas FieldDevelopment Plans, para.2.5.1 available at https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/265842/FDP_guidance_notes_�ovember_2013_web.pdf [Accessed 25 April2016].

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(i) Purchase—often an extension into an adjacent concession is small and ofminimal interest to the concession holders. �evertheless, to preclude thepossibility of a competitive development, the owners wishing to developthe common reservoir may offer to acquire the interest in the extension.The purchase can be structured along traditional lines where the area of theconcession containing the extension is carved out and the extraction rightstransferred or as a one off payment in exchange for a commitment that theparties having rights to the extension will not drill into the commonreservoir and extract petroleum therefrom.

Purchasing is often secured where the extension is demonstrably small.A purchase price is more complicated to agree where the extension is largerand the range of possible reserves more uncertain.

(ii) Fixed interests—where agreement cannot be landed on the purchase pricean alternative is to enter into a UUOA but to fix equities from the outset sothat there are no redeterminations. In principle, this is similar to the USpractice of “pooling” where multiple leaseholders with interests in one ormore tracts “pool” their interests together, fixing their interests, in order toreceive regulatory consent—in the case of US oil producing states, to drillin compliance with local spacing regulations, but elsewhere to proceed witha development. This avoids the issues associated with redetermination asoutlined above but enables the owners of the extension to participate in thedevelopment.

Parties may agree to fix interests where the extension is small or wherethe owners of the extension hold similar interests in the concession area inwhich the discovery has been made, both of which militate against enteringinto the complications of redetermination.

(iii) Cross assignment—if agreement can landed between two or moreconcession holders on the distribution of reserves across the respectiveconcession areas, then they may enter into a cross assignment whereby theinterests of each participant is “equalised” across all concession areas,thereby fixing the interests in, not only the common reservoir, but acrossthe concessions.

An example of a cross-assignment is the UK’s current largest producingfield, Buzzard, which straddles two production licences (P.928(S) andP.986) and, as such, could have been unitised. However, the two concessiongroups had, similar if not identical, owners and a common operator. Thisundoubtedly facilitated an agreement to fix equities across both licences(and not just the common reservoir) prior to FDP approval whenrecoverable reserves from Buzzard were estimated at ~400 million barrelsand plateau production forecast at 80,000 boe/day.32 However, the recordshows that Buzzard plateaued at 220,000 boe/day (which at the time ofwriting it continues to produce at) with recoverable reserves of 775 millionbbls.33 These new reserves will almost certainly be distributed across thetwo licence areas disproportionately to the fixed equity interests. Whilst the

32 See Buzzard field development plan press release at https://www.encana.com/news-stories/news-releases/details.html?release=615219 [Accessed 25 April 2016].33 See Buzzard field owner, Oranje-�assau Energie’s public statement at http://www.onebv.com/Buzzard [Accessed 25 April 2016].

ALTER�ATIVES TO REDETERMI�ATIO�

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merits of fixing the Buzzard interests will remain confidential to theowners, it provides both a good example of the potential for a commonreservoir to expand beyond expectations as further information isaccumulated from production operations and a caution to fixing equitiesearly.

CROSS-BORDER DEVELOPME�T OPTIO�S

Like the unitisation of domestic fields, a petroleum reservoir could straddle theonshore or offshore border between two or more sovereign states. In such asituation the process of unitisation is complicated by the need for the relevantstates to agree to the unitisation framework before the process of negotiating theUUOA between the participating E&P companies can commence (and particu-larly so where there are ongoing disagreements between those states relating totheir territorial or maritime boundary lines). In the �orth Sea these inter-stateagreements have been the subject of field to field treaties34 although morerecently the UK Government has agreed framework terms with the Governmentsof �orway and �orthern Ireland.35

The commercial dynamics which apply to the negotiation of the terms of sucha Treaty should be fairly similar to the negotiations which take place between theparticipating E&P companies but with some added nuances reflecting therespective governments’ wider public interest mandate. Each state will wish toobtain the maximum equity position for the participants on its side of theboundary so as to maximise its take from royalty, tax or other fiscal benefits. Thelocation of the production station (onshore) or platform (offshore) will also be akey matter as it will likely determine the regulatory framework applicable such ashealth and safety legislation, employment law and the fiscal terms that apply toopex, capex and decommissioning. The evacuation route for produced petroleumwill also be important as the landing point for petroleum will trigger a significantuplift in local economic activity, including jobs and downstream processingoperations, such as petrochemical plants and power generation, as well asimproving the landing state’s energy security.

A cross-border unitisation should not be confused with a joint developmentzone (JDZ) arrangement. The terms which govern the establishment of a JDZ likethe terms of a cross-border unitisation, are settled between states but typicallyapply in respect to a disputed geographical area that may or may not holddiscovered reserves. The relevant states form a joint management committee thatsupervises operations within the JDZ which at least allows petroleum exploration34 See Taylor et al., Joint Operating Agreements (1992), p.71 and English p.100. The Frigg FieldReservoir Agreement between the Governments of the UK and �orway available online athttps://treaties.un.org/doc/Publication/U�TS/Volume%201098/volume-1098-I-16878-English.pdf[Accessed 25 April 2016].35 See the Framework Agreement between the Government of the United Kingdom of Great Britainand �orthern Ireland and the Government of the Kingdom of �orway concerning Cross-BoundaryPetroleum Co-operation (effective 10 July 2007) available at https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/243184/7206.pdf [Accessed 25 April 2016]. And neither iscross-border unitisation a uniquely European phenomenon: see, for example, the agreements betweenthe governments of Australia and Timor Leste relating to the unitisation of the Sunrise andTroubadour fields in the Timor Sea.

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(and even production) operations to commence, notwithstanding that sovereigntyover the area is claimed (and disputed) by two or more states. If a petroleumdiscovery is made then, no matter where it lies in relation to the claimed borders,each state will share in the resultant production according to defined terms,usually equally.

JDZs exist, for example, between �igeria and São Tomé and Principe in theGulf of Guinea, between Kuwait and Saudi Arabia and between Malaysia,Thailand and Vietnam.

CO�CLUSIO�

Unitisation (and redetermination) remains the oil and gas industry’s bestmechanism to manage the unknown distribution of petroleum in a commonreservoir. It seeks to identify the size and distribution of reserves held in acommon reservoir by creating a production and cost banking type of arrangementthat can be revisited as more geological information provides better and moreaccurate assessments. The process is inherently flawed because geologicaluncertainty can never be completely resolved until the end of field life. Whilst theflaws are inherent, understanding the redetermination process from the inceptionwill provide some comfort that unit owners receive as fair a distribution of costand production as is possible.

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CO�CLUSIO�

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unitisation and redetermination—sean rush · 4 m. hammerson, upstream oil and gas: cases,...

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